Subsea Intervention Plug Pulling Device

ABSTRACT

A plug pulling device includes an elongated housing comprising a production tree connection interface, a shifting tool disposed within and along a substantial length the housing and comprising a distal end configured to couple to a tubing plug, and a seal disposed within the housing and formed around a portion of the shifting tool. The seal isolates a first portion of the housing from a second portion of the housing. The second portion of the housing is adjacent to the production tree connection interface. The shifting tool is configured to move partially in and out of the first portion of the housing when there is a pressure differential between the first portion of the housing and an environment external to the first portion of the housing.

TECHNICAL FIELD

The present application relates to retrieving a tubing plug that is placed within a production tubing of a well. Specifically, the present application relates to systems and methods for retrieving the tubing plug.

BACKGROUND

Well completion is the process of preparing a borehole for controlled production of natural resources. Typically, a well is created by alternatingly drilling and installing a series of telescoping casings. For example, in certain subsea well completions, a first hole of a certain depth is drilled from the seafloor and fitted with a conductor casing. Space between the outer perimeter of the conductor casing and the first hole is filled with cement or other agent to stabilize and set the casing within the first hole. A second hole is then drilled from the bottom of the first hole, in which the second hole has a smaller diameter then the first hole. Likewise, the second hole is fitted with a casing, and the space between the outer perimeter of the casing and the second hole is filled with cement or another agent. A variable number of telescoping-sized holes and can be drilled and cased, collectively known as a casing string. The depth of each hole and casing segment and the total number of segments depends on various factors such as rock stress, pore pressure, required hole diameter and depth, and so forth. A segment of the casing string known as a surface casing extends to or above the seafloor and terminates at a wellhead located at or near the surface of the seafloor. A blowout preventer (BOP) is typically attached to the wellhead to maintain pressure and security of the well during remaining well sections and completions. Generally, a completed well further includes a production tubing substantially extending from the tubing hanger at the mud line to the bottom of the well, through which the resources are brought to a pipeline for production. In order to facilitate recovery of resources from surrounding formations, certain portions of the casing string and/or production tubing are perforated to allow fluids from surrounding formations to flow into the production tubing. The production tubing is typically hung from a tubing head spool or the wellhead at the surface of the seafloor.

As another mode of isolating the well from the surface environment (i.e., to prevent uncontrolled flow of resources to the surface) during completions, a tubing plug is disposed within the production tubing and tested. When it is known that the tubing plug successfully isolates the well, the BOP can be removed and a production tree, also known as a Christmas tree, can be installed onto the wellhead to provide production and flow control of the well. With the tubing plug still in place, the production tree is tested. Before the well can be put into production, the tubing plug needs to be removed. Traditionally, in order to remove the tubing plug from the production tubing, the BOP is reinstalled to provide a mechanical barrier for the well during retrieval of the tubing plug. Deploying a BOP and retrieving the plug typically requires the use of a mobile offshore drilling unit (MODU). However, a MODU is a very large and highly complex piece of equipment designed for heavy duty operations such as drilling. As a result, MODUs are very costly to operate, often costing millions of dollars. Additionally, such conventional plug retrieval is performed through a slickline operation, in which a thin wire with a tool attached is run down-hole into the production tubing to retrieve the plug. These operations are susceptible to certain issues such as wire breakage, in which the wire and the tool are dropped down-hole. Thus, the wire and tool need to be fished out before attempting to operate the well, adding time and cost to the operation. Thus, it would be beneficial and highly cost effective to eliminate the need to use a MODU or slickline operation for plug pulling processes.

SUMMARY

In general, in one aspect, the disclosure relates to a plug pulling device. The plug pulling device includes a housing including a closed top end and an open bottom end. The plug pulling device further includes a shifting tool including a stem and a pulling tool disposed at a distal end of the stem, in which the shifting tool is movable in and out of the housing via the bottom end. The plug pulling device also includes a circular seal disposed within the housing and around the shifting tool, forming a fluid tight seal between the shifting tool and the housing. The shifting tool is slidable with respect to the seal and along a length of the housing. The seal divides the housing into a first chamber and a second chamber. The first chamber is defined between the top end of the housing and the seal, and the second chamber is defined between the seal and the bottom end. The first chamber and the second chamber are isolated from each other by the seal. The plug pulling device further includes a first hot stab and a second hot stab. The first hot stab is coupled to the first chamber and configured to deliver hydraulic fluid in and out of the first chamber. The second hot stab is coupled to the second chamber and configured to deliver hydraulic fluid in and out of the second chamber.

In another aspect, the disclosure can generally related to a subsea intervention device. The subsea intervention devices includes an elongated housing including a production tree connection interface. The subsea intervention device further includes a shifting tool disposed within and along a substantial length of the housing and having a distal end configured to couple to a tubing plug. The subsea intervention device also includes a seal disposed within the housing and formed around a portion of the shifting tool. The seal isolates a first portion of the housing from a second portion of the housing. The second portion of the housing is adjacent to the production tree connection interface. The shifting tool is configured to move partially in and out of the first portion of the housing when there is a pressure differential between the first portion of the housing and an environment external to the first portion of the housing.

In another aspect, the disclosure can generally relate to a method of pulling a tubing plug from a production tubing. The method includes coupling a plug pulling device to a production tree of a well, in which the plug pulling device includes a housing and a shifting tool disposed within the housing. The housing is also divided into a first chamber and a second chamber by a seal. The first chamber is isolated from the second chamber and the second chamber couples to the production tree. The method also includes opening one or more valves of the production tree, and pushing the shifting tool substantially out of the first chamber and into the production tree and the well coupled to the production tree until the shifting tool latches onto the tubing plug disposed within the well. The method further includes pulling the shifting tool back into the first chamber along with the tubing plug.

These and other aspects, objects, features, and embodiments will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings illustrate only example embodiments of systems and methods for pulling a tubing plug from a production tubing in a subsea well, and are therefore not to be considered limiting of its scope, as the disclosures herein for pulling a tubing plug from a production tubing may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positioning may be exaggerated to help visually convey such principles. In the drawings, reference numerals designate like or corresponding, but not necessarily identical, elements. The methods shown in the drawings illustrate certain steps for carrying out the techniques of this disclosure. However, the methods may include more or less steps than explicitly illustrated in the example embodiments. Two or more of the illustrated steps may be combined into one step or performed in an alternate order. Moreover, one or more steps in the illustrated methods may be replaced by one or more equivalent steps known in the art to be interchangeable with the illustrated step(s). In one or more embodiments, one or more of the features shown in each of the figures may be omitted, added, repeated, and/or substituted. Accordingly, embodiments of the present disclosure should not be limited to the specific arrangements of components shown in these figures.

FIG. 1 illustrates a cross-sectional representation of a subsea well system for use with a plug pulling device at a first stage of well completion, in accordance with example embodiments of the present disclosure;

FIG. 2 illustrates a cross-sectional representation of a well system for use with a plug pulling device at a second stage of well completion, in accordance with example embodiments of the present disclosure;

FIG. 3 illustrates a cross-sectional representation of a well system for use with a plug pulling device in a third stage of well completion, in accordance with example embodiments of the present disclosure;

FIG. 4 illustrates a cross-sectional representation of a plug pulling device in an initial retracted state coupled to a well system, in accordance with example embodiments of the present disclosure;

FIG. 5 illustrates a cross-sectional representation of a well system with a plug pulling device in a deployed state, in accordance with example embodiments of the present disclosure;

FIG. 6 illustrates a cross-sectional representation of a well system with a plug pulling device in a retrieved state, in accordance with example embodiments of the present disclosure;

FIG. 7 illustrates a method of pulling a plug from a subsea well, in accordance with example embodiments of the present disclosure; and

FIG. 8 illustrates another method of pulling a plug from a subsea well, in accordance with example embodiments of the present disclosure.

DETAILED DESCRIPTION OF EXAMPLE EMBODIMENTS

Example embodiments directed to pulling a plug from a subsea well will now be described in detail with reference to the accompanying figures. Like, but not necessarily the same or identical, elements in the various figures are denoted by like reference numerals for consistency. In the following detailed description of the example embodiments, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure herein. However, it will be apparent to one of ordinary skill the art that the example embodiments herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Designations such as “first” and “second” are merely used to distinguish between distinct features, and not meant to limit the number of features. Furthermore, in certain embodiments, such distinct features are not precluded from having the same value, if applicable. Descriptions such as “top”, “bottom”, “distal”, and “proximal” are merely used to distinguish between different portions of an element or component and are not meant to imply an absolute orientation.

In certain example embodiments, production fluid as described herein is one or more of any solid, liquid, and/or vapor that can be found in subterranean formations. Examples of production fluid can include, but are not limited to, crude oil, natural gas, water, steam, and hydrogen gas. Production fluid can be called other names, including but not limited to down hole fluid, reservoir fluid, a resource, and a field resource. In certain example embodiments, the techniques provided herein are directed towards well completions and well interventions in subsea environments, including both deep water and shallow water environments.

The present disclosure provides a subsea intervention plug pulling device. In certain example embodiments, the plug pulling device is a self-contained device which attaches to a production tree and is configured to remove a tubing plug from a production tubing or well without the need for an intervening blowout preventer (BOP) stack or lower marine riser package (LMRP). The plug pulling device makes use of the valves of the production tree as barriers as it recovers the tubing plug. As discussed above, attaching a BOP to a production tree requires the use of a costly mobile offshore drilling unit (MODU). Thus, as the plug pulling device eliminates the need for BOP attachment for plug pulling, the MODU is likewise unnecessary, decreasing the time and cost of the plug pulling operation.

Referring now to the drawings, FIG. 1 illustrates a subsea well system 100 at a first stage of completion for use with a plug pulling device, in accordance with example embodiments of the present disclosure. Referring to FIG. 1, the well system includes a wellbore 102 formed in an underwater subterranean formation 104. In certain example embodiments, the subterranean formation 104 includes one or more of a number of formation types, including but not limited to, shale, limestone, sandstone, clay, sand, and salt. In certain example embodiments, the subterranean formation 104 also includes one or more reservoirs in which one or more resources (e.g., oil, gas) can be located.

In certain example embodiments, the wellbore 102 has one or more of a number of segments, and each segment has a one or more of a number of dimensions. Examples of such dimensions include, but are not limited to, a diameter, a curvature, a depth (i.e., length), a horizontal displacement, and the like. In certain example embodiments, the well 100 includes a casing string 106 disposed within the wellbore 102. In certain example embodiments, the casing string 106 comprises a casing segment fitted to each of the segments of the wellbore 102. In one example embodiment, and as illustrated in FIG. 1, the casing string 106 includes a conductor casing 108, a surface casing 110, and a production casing 112. In certain example embodiments, the casing string 106 includes more or less segments than those provided in the present example. A segment of casing string 106 can also be known as a casing tube, casing pipe, or casing. Each casing pipe of the casing string 106 has a length and a width (i.e., outer diameter). The length of a casing pipe can vary. For example, a common length of a casing pipe is approximately 40 feet. The length of a casing pipe can be longer (e.g., 60 feet) or shorter (e.g., 10 feet) than 40 feet. The width of the casing pipe can also vary and can depend on the cross-sectional shape of the casing pipe. In certain example embodiments, each subsequent casing pipe has a width smaller than the previous casing pipe and is disposed deeper within the borehole 102. Thus, in certain example embodiments, the casing string 106 is made up of telescoping casing pipes. The length and width of the casing pipes as well as the number of casing pipes that make up the casing string 106 are determined by data collected regarding various conditions of the environment and the subterranean formation 104 and the desired well completion.

As illustrated in FIG. 1, the conductor casing 108 is the widest casing and includes a proximal end 109 a substantially at the seafloor 118 or surface of the subterranean formation 104 and a distal end 109 b at a first distance from the seafloor 118. The surface casing 110 is narrower than the conductor casing 108 and fits therethrough. In certain example embodiments, the surface casing 110 includes a proximal end 111 a extending above the seafloor 118 and a distal end 111 b at a second distance from the seafloor 118. The certain example embodiments, the second distance is larger than the first distance and the surface casing 110 extends deeper into the subterranean formation 104. The production casing 112 is the smallest and deepest casing of the casing string 106. As discussed above, certain other example wells 100 may include more casing segments. In certain example embodiments, one or more of the casing segments are coupled to or hung from another casing segment by a hanger 116, which couples the two casing segments. In certain example embodiments, one or more of the casing segments further include casing shoes 114 at respective distal ends. The casing shoes 114 help guide the casing pipe through obstacles when being deposited into the wellbore 102. The casing string 106 is made of one or more of a number of suitable materials, including by not limited to steel. In certain example embodiments, the casing string 106 is set along the substantial length of the wellbore 102.

In certain example embodiments, the casing string 106 is cemented to the walls of the wellbore 102. A cement slurry is injected into the space between the casing string 106 and the wellbore 102 walls and fills the gaps between the wellbore 102 and the casing string 106. The cement layer can provide various functional benefits, including but not limited to, stabilizing and securing the casing string 106 in the wellbore 102, and protecting and isolating the completion. In certain example embodiments, each casing pipe is individually cemented to the respective wellbore segment.

In certain example embodiments, the well system 100 further includes a tubing head spool 122 coupled to the proximal end 111 a of the surface casing 110 or the wellhead. In certain example embodiments, the tubing head spool 122 is coupled around the proximal end 111 a of the surface casing 110 via a high pressure seal. The tubing head spool 122 is configured to hang production tubing 202 (FIG. 2) down the wellbore 102 and seal the annulus between the surface casing 110 and the production tubing 202. The size and pressure rating of the tubing head spool 122 can vary based on one or more of a number of factors, including but not limited to, the weight of the production tubing 202, the weight of the casing string 106, and formation conditions. In certain example embodiments, the well system 100 includes a hub connection 120 coupled to the tubing head spool 122. The hub connection 120 couples the well to a flow line, which delivers the resources (e.g., gas, oil) produced from the well to a manifold and/or production facility, where the resources are collected.

FIG. 2 illustrates the well system 100 at a second stage of completions, in accordance with example embodiments of the present disclosure. Referring to FIG. 2, the well system 100 further includes production tubing 202 disposed within the wellbore 102 and concentrically traversing the casing 106. As discussed above, the production tubing 202 is hung from the tubing head spool 122. The production tubing 202 can also be known as tubing or tubing string. In certain example embodiments, the production tubing 202 includes a number of tubing pipes that are mechanically coupled to each other end-to-end, usually with mating threads. The tubing pipes of the production tubing 202 can be mechanically coupled to each other directly or using a coupling device, such as a coupling sleeve. In certain example embodiments, the production tubing 202 extends from above the seafloor to substantially the bottom of the wellbore 102 and/or casing string 106.

Each tubing pipe of a tubing string 202 has a length and a width (e.g., outer diameter). The length of a tubing pipe can vary. For example, a common length of a tubing pipe is approximately 30 feet. The length of a tubing pipe can be longer (e.g., 40 feet) or shorter (e.g., 10 feet) than 30 feet. The width of a tubing pipe can also vary and can depend on one or more of a number of factors, including but not limited to the inner diameter of the casing pipe. For example, the width of the tubing pipe is less than the inner diameter of the casing pipe. The width of a tubing pipe can refer to an outer diameter, an inner diameter, or some other form of measurement of the tubing pipe. Examples of a width in terms of an outer diameter can include, but are not limited to, 7 inches, 5 inches, and 4 inches.

In certain example embodiments, a distal end 216 of the production tubing 202 is located toward the bottom of the wellbore 102, and a proximal end 212 of the production tubing 202 is located at or above the seafloor 118 and coupled within the tubing head spool 122. The size (e.g., outer diameter, length) of the production tubing 202 can be determined based, in part, on the size and configuration of the casing string 106 and/or the wellbore 102. The tubing can be made of one or more of a number of suitable materials, including but not limited to steel. The one or more materials of the production tubing 202 can be the same or different than the materials of the casing string 106.

The production tubing 202 substantially traverses the length of the well and is configured to deliver the resources from the well to the surface 118. In certain example embodiments, the production tubing 202 includes one or more valves, such as a first valve 206 and a second valve 208. The valves 206, 208 can be actuated to act as mechanical barriers when it is desired to impede the upward flow of fluid resources from the subterranean formation 104. In certain example embodiments, one or more of the valves 206, 208 may have an acceptable leak rate.

In certain example embodiments, the production tubing 202 is hung from the tubing head spool 122 at the proximal end 212 such that resources are directed to reach the surface via the production tubing 202. Furthermore, in certain example embodiments, the production tubing 202 is coupled to the casing 106 via a tubing hanger 204. The tubing hanger further secures and stabilizes the production tubing 202 within the casing 106 and the wellbore 102.

In certain example embodiments, the cased well 100 and production tubing 202 are not immediately in communication with the flow of resource in the reservoir or the subterranean formation 104 after installation. Thus, a plurality of perforations 214 are made in certain portions of the well to couple the well to the resources. In certain example embodiments, the plurality of perforations 214 are made through the production casing 112 and into the subterranean formation 104. In certain example embodiments, the plurality of perforations 214 are made through the production casing 112 and the production tubing 202 and into the subterranean formation 104. Thus, the well is in fluid communication with the reservoir and the resources can be brought to the surface through the production tubing 202.

In certain example embodiments, the well system 100 includes a tubing plug 210 disposed within the production tubing 202. The tubing plug 210 isolates the well and the reservoir from the surface 118 and the upper portion of the well system 100. The tubing plug 210 acts as another mechanical barrier configured to impede the upward flow of resources from the reservoir when the tubing plug 210 is disposed in the production tubing 202. The tubing plug 210 is installed when well isolation is desired and can be removed when the well is put into production. In certain example embodiments, the tubing plug 210 is installed in the production tubing 202 after the plurality of perforations 214 are made and before the well is put into production. In certain example embodiments, the well is coupled to a BOP when the tubing plug 210 is installed. The tubing plug 210 is to be removed before the well can produce.

FIG. 3 illustrates the well system 100 in a third stage of completion, in accordance with example embodiments of the present disclosure. In certain example embodiments, after the tubing plug 210 is installed in the production tubing 202 and is tested as an effective well isolation barrier, the BOP (not shown in FIG. 3) can be removed and a production tree 302 is placed on top of and fastened to the tubing head spool 122. In certain example embodiments, the production tree 302 includes a first valve 304 and a second valve 306, as shown in the simplified representation illustrated in FIG. 3. However, in certain example embodiments, the production tree 302 is much more complex and includes a plurality of various valves, spools, pressure gauges, chokes, and the like, which are used to control the flow and recovery of production fluid. In certain example embodiments, such as that illustrated in FIG. 3, the production tree 302 is a vertical production tree. However, in certain other example embodiments of the present disclosure, the production tree 302 is a horizontal production tree.

FIG. 4 illustrates the well system 100 with a plug pulling device 402, in accordance with an example embodiment of the present disclosure. Referring to FIG. 4, the plug pulling device 402 includes a closed top end 420 and an open bottom end 422. In certain example embodiments, the bottom end 422 is securely coupled to the top of the production tree 302 such that the junction between the plug pulling device 402 and the production tree 302 is sealed. In certain example embodiments, the bottom end 422 of the plug pulling device 402 includes a mating end similar to that of a BOP and configured to latch onto a standard production tree connection. The plug pulling device 402 includes a linear inner cavity 405 extending from the top end 420 to the bottom end 422. The plug pulling device 402 further includes an elongated shifting tool 408 disposed within the inner cavity 405. The shifting tool 408 includes a stem 424 and a pulling tool 410 disposed at a distal end of the stem 424. In certain example embodiments, the shifting tool 408 has a length substantially similar to or smaller than the length of the inner cavity 405.

In certain example embodiments, the plug pulling device 402 includes one or more stabilizing guides 412 disposed within the inner cavity 405 and surrounding the shifting tool 408. The stabilizing guides 412 provide support for the shifting tool 408 and keep the shifting tool 408 straight and directed over center. In certain example embodiments, the stabilizing guides 412 are concentric rings. The plug pulling device 402 further includes a seal 414 disposed in the inner cavity 405 between the shifting tool 408 and the inner surface of the housing 403. The seal 414, having the shifting tool 408 disposed therethrough, separates the inner cavity 405 of the housing 403 into a first chamber 404 and a second chamber 406, such that the first chamber 404 is sealed from the second chamber 406. In certain example embodiments, the first chamber 404 is defined between the closed top end 422 and the seal 414, and the second chamber 406 is on the opposite side of the seal 414 and adjacent to the open bottom end 422. In certain example embodiments, the seal 414 is dynamic, allowing the shifting tool 408 is travel up and down therethrough and between the first chamber 404 and the second chamber 406 while maintaining isolation between the first chamber 404 and the second chamber 406. In certain example embodiments, the seal 414 is fabricated from a low-temperature resistant and corrosion resistant polymer material. In certain example embodiments, the first chamber 404 is filled with hydraulic fluid and is communicative with one or more hydraulic fluid sources (not shown). In certain example embodiments, the plug pulling device 402 includes at least a first hot stab 416 and a second hot stab 418. The first hot stab 416 is coupled to the first chamber 404 and the second hot stab 418 is coupled to the second chamber 406. The hot stabs 416, 418 are used to pump hydraulic fluid in and out of the respective chambers 404, 406. In certain example embodiments, the hot stabs 416, 418 are coupled to a control panel (not shown) which controls actuation of the hot stabs 416, 418. In certain example embodiments, the hot stabs 416, 418 are actuated by a remotely operated vehicle (ROV). In such embodiments, the ROV includes a reservoir of hydraulic fluid, which provides a source of hydraulic fluid for the hot stabs 416, 418. In certain example embodiments, the plug pulling device 402 includes additional hot stabs (not shown), including but not limited to, hot stabs for actuating and testing locks and valves.

The plug pulling device 402 is configured to send the shifting tool 408 downward through the production tree 302 and into the production tubing 202 until the pulling tool 410 mates with the tubing plug 210. After the pulling tool 410 becomes mechanically coupled to the tubing plug 210, the plug pulling device 402 lifts the shifting tool 408 back up into the housing 403. As the shifting tool 408 is lifted upward, the tubing plug 210 which is mechanically coupled to the pulling tool 410, is lifted upward as well and retrieved. Thus, the tubing plug 210 is removed from the production tubing 202. Inner workings of the plug pulling device 402 are described in further detail below with respect to FIGS. 4, 5, and 6. FIG. 4 illustrates the plug pulling device 402 in an initial retracted state, prior to deployment of the shifting tool 408 into the production tubing 202, in accordance with example embodiments of the present disclosure. FIG. 5 illustrates the plug pulling device 402 in a second state, in which the shifting tool is deployed into the production tubing 202 and mated with the tubing plug 210, in accordance with example embodiments of the present disclosure. FIG. 6 illustrates the plug pulling device 402 in a third retracted state, in which the shifting tool is pulled back into the housing 403 with the retrieved tubing plug, in accordance with example embodiments of the present disclosure.

Referring to FIG. 4, when the plug pulling device 402 is in an initial retracted position, the shifting tool 408 is substantially within the first chamber 404 and contained within the inner cavity 405 of the plug pulling tool 402. The valves 304, 306 of the production tree 302 are closed when the plug pulling device 402 is first latched onto the production tree 302. After the plug pulling device 402 is latched onto the production tree 302 and the connection is sealed, the valves 304, 306 can be opened as the plug pulling device 402 provides a closed and isolated environment for the well, or acts as a barrier. Furthermore, the valves 304, 306 need to be open in order for the shifting tool 408 to reach the production tubing 202. Pressure is then increased inside the first chamber 404 to push the shifting tool 408 substantially out of the first chamber 404 and towards the production tubing 202. As the seal 414 isolates the first chamber 404 and the shifting tool 408 is slidable with respect to the seal, pressure increase within the first chamber 404 is mitigated by urging the shifting tool 408 further out of the first chamber 404, which increases the available volume within the first chamber 404. In the example embodiment described herein, it should be noted that “out of the first chamber” refers to portions of the shifting tool 408 and not to the entire shifting tool 408. In other words, in certain example embodiments, at least a portion of the stem 424 remains within the first chamber 404 during the entire operation and some portion of the stem is always disposed within the seal 414 such that the first chamber 404 is always isolated from the second chamber 406.

In certain example embodiments, pressure is increased within the first chamber 404 by pumping additional hydraulic fluid into the first chamber 404. In certain example embodiments, the ROV attaches to the first hot stab 416, which is coupled to the first chamber 404, and controls the hot stab 416 to pump hydraulic fluid into the first chamber 404 via the hot stab 416. When the pressure inside the first chamber 404 is large enough to cause a downward force on the shifting tool 408 that overcomes an upward force on the shifting tool generated by pressure in the second chamber 406, the shifting tool 408 begins to move downward towards the tubing plug 210.

Referring to FIG. 5, as more hydraulic fluid is pumped into the first chamber 404, the shifting tool 408 continues to be further displaced out of the first chamber 404. Thus, the shifting tool 408 travels further towards the tubing plug 210. In certain example embodiments, the shifting tool 408 traverses the production tree 302 via the open valves 304, 306, to reach the tubing plug 210. In certain example embodiments, the stabilizing guides 412 keep the shifting tool 408 straight and centered as the shifting tool 408 travels towards the tubing plug 210. Hydraulic fluid continues to be pumped into the first chamber 404 until the shifting tool 408 latches onto the tubing plug 210. In certain example embodiments, the tubing plug 210 is shaped and fitted within the production tubing 202 such that the tubing plug 210 will not travel further down the production tubing 202. As such, when the shifting tool 408 reaches the tubing plug 210, the shifting tool 408 will stop traveling further downward. In certain example embodiments, this is indicated by pressure measurement within the first chamber 404.

In certain example embodiments, the pressure within the first chamber 404 urges the pulling tool 410 into mechanical engagement with the tubing plug 210. Specifically, in certain example embodiments, the pulling tool 410 includes a collapsible profile which collapses into the tubing plug 210 until the pulling tool 410 is disposed in an intended resting space of a complementary shape within the tubing plug 210. In certain example embodiments, the pulling tool 410 breaks one or more pins within the tubing plug 210. The pulling tool 410 then expands within the tubing plug 210 and is latched within the tubing plug. Thus, the tubing plug 210 is attached to the shifting tool 408 and will travel with the shifting tool 408. In certain example embodiments, the tubing plug 210 and the pulling tool 410 utilize various other mechanical mating mechanisms and techniques which allow the pulling tool 410 to engage with the tubing plug 210 such that the tubing plug 210 can be pulled up with the pulling tool 410.

After the shifting tool 408 latches onto the tubing plug 210 via the pulling tool 410, the shifting tool 408 is pulled up and out of the production tubing 112 and production tree 302 and back into the inner cavity 405 of the plug pulling device 402. In certain example embodiments, the shifting tool 408 is pulled up by decreasing the pressure in the first chamber 404 relative to the pressure in the second chamber 406, thereby causing a pressure differential which urges the shifting tool 408 to travel upward and into the first chamber 404. In certain example embodiments, this is done by increasing the pressure in the second chamber 406, which is in fluid communication with the production tree 302 and the well when the valves 304, 306 are open. In certain such example embodiments, the ROV attaches to the second hot stab 218, which is coupled to the second chamber 406, and pumps hydraulic fluid into the second chamber 406 to increase the pressure in the second chamber 406. In certain example embodiments, when the pressure in the second chamber 408 becomes large enough to overcome the pressure in the first chamber 404, the shifting tool 408 begins to move upward and back into the first chamber 404. In certain example embodiments, as the shifting tool 408 moves further into the first chamber 404, the hydraulic fluid within the first chamber is allowed to bleed off. In another example embodiment, the pressure in the first chamber 404 is reduced by removing hydraulic fluid from the first chamber 404. Thus, as the pressure in the first chamber 404 gradually decreases, the pressure in the second chamber 406 becomes relatively larger and the pressure differential between the first and second chambers 404, 406 urges the shifting tool 408 to move back towards the first chamber 404.

Referring to FIG. 6, eventually, the pressure differential created between the first chamber 404 and the second chamber 406 brings the shifting tool 408 back into the first chamber 404 along with the tubing plug 210. After the shifting tool 408 is moved out of the production tree 302, the valves 304, 306 of the production tree 302 are closed and tested. The plug pulling device 402 is then decoupled from the production tree 302 and a cap is put on the production tree 302 in place of the plug pulling device 402. In certain example embodiments, the well system 100 is now ready to be put into production. It should be understood that, in certain example embodiments, the foregoing steps can be reversed so that the plug pulling device 402 is used for plug installation operations.

FIG. 7 illustrates a method 700 of pulling a plug from a subsea well, in accordance with example embodiments of the present disclosure. Example method 700 includes attaching a plug pulling device onto a production tree of a well. In certain example embodiments, the plug pulling device includes a housing and a shifting tool movably disposed within the housing (step 702). The method 700 further includes opening one or more valves of the production tree such that the plug pulling device is communicative with a production tubing of the well (step 704). The method 700 further includes pushing the shifting tool into the production tubing until the shifting tool mates with a plug disposed within the production tubing (step 706). The method 700 also includes pulling the shifting tool out of the production tubing and back into the housing of the plug pulling device along with the plug (step 708). Thus, the plug is retrieved. In certain example embodiments, the valves of the production tree are then closed and the plug pulling device is decoupled from the production tree.

FIG. 8 illustrates another method 800 of pulling a plug from a subsea well, in accordance with example embodiments of the present disclosure. Example method 800 includes attaching a plug pulling device onto a production tree of a well. In certain example embodiments, the plug pulling device includes a housing and a shifting tool movably disposed within the housing (step 802). The method 800 further includes opening one or more valves of the production tree such that the plug pulling device is communicative with a production tubing of the well (step 804). The method 800 further includes increasing relative pressure in a first chamber of the housing until the shifting tool travels into a production tubing of the well and mates with a tubing plug (step 806). In certain example embodiments, this is done by injecting hydraulic fluid into the first chamber. The method 800 also includes decreasing relative pressure in the first chamber until the shifting tool and the tubing plug travel back into the housing (step 808). In certain example embodiments, this is done by removing hydraulic fluid from the first chamber. Thus, the plug is retrieved. In certain example embodiments, the valves of the production tree are then closed and the plug pulling device is decoupled from the production tree.

In certain example embodiments, the plug pulling tool 402 can be deployed from a small-scale vessel rather than a MODU. The vessel has a much smaller cost of operation compared to the MODU. A plug pulling operation utilizing the presently disclosure techniques also takes less time than the conventional operation utilizing a MODU. Thus, the presently disclosed techniques provide significant improvements in the cost and time efficiency of subsea plug pulling operations.

Although embodiments described herein are made with reference to example embodiments, it should be appreciated by those skilled in the art that various modifications are well within the scope and spirit of this disclosure. Those skilled in the art will appreciate that the example embodiments described herein are not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the example embodiments, equivalents of the elements shown therein will suggest themselves to those skilled in the art, and ways of constructing other embodiments using the present disclosure will suggest themselves to practitioners of the art. Therefore, the scope of the example embodiments is not limited herein. 

What is claimed is:
 1. A plug pulling device, comprising: a housing comprising a closed top end and an open bottom end; a shifting tool comprising a stem and a pulling tool disposed at a distal end of the stem, wherein the shifting tool is movable in and out of the housing via the bottom end; a circular seal disposed within the housing and around the shifting tool, and forming a fluid tight seal between the shifting tool and the housing, the shifting tool being slidable with respect to the seal and along a length of the housing, wherein the seal divides the housing into a first chamber and a second chamber, the first chamber defined between the top end of the housing and the seal, and the second chamber defined between the seal and the bottom end, wherein the first chamber and the second chamber are isolated from each other by the seal; a first hot stab coupled to the first chamber configured to deliver hydraulic fluid in and out of the first chamber; and a second hot stab coupled to the second chamber configured to deliver hydraulic fluid in and out of the second chamber.
 2. The plug pulling device of claim 1, further comprising at least one stabilizer guide disposed within the housing and surrounding the stem of the shifting tool.
 3. The plug pulling device of claim 1, wherein the bottom end of the housing comprises a standard production tree mating feature.
 4. The plug pulling device of claim 1, wherein the production tree is coupled to a well comprising a tubing plug, the production tree comprising at least one valve configured to open or isolate the well.
 5. The plug pulling device of claim 4, wherein the shifting tool is configured to travel away from the top end of the housing towards the tubing plug until the pulling tool latches onto the tubing plug and travel back towards the top end of the housing after the pulling tool latches onto the tubing plug, wherein the tubing plug travels towards the top end of the housing with the shifting tool.
 6. The plug pulling device of claim 5, wherein the shifting tool travels towards the tubing plug when pressure in the first chamber overcomes pressure in the second chamber, wherein the second chamber is communicative with the production tree.
 7. The plug pulling device of claim 5, wherein the shifting tool moves back towards the top end of the housing when pressure in the second chamber overcomes pressure in the first chamber, wherein the second chamber is communicative with the production tree.
 8. The plug pulling device of claim 6, wherein pressure in the first chamber overcomes pressure in the second chamber through pumping hydraulic fluid into the first chamber via the first hot stab.
 9. The plug pulling device of claim 7, wherein pressure in the second chamber overcomes pressure in the first chamber through pumping hydraulic fluid into the second chamber via the second hot stab.
 10. The plug pulling device of claim 7, wherein pressure in the second chamber overcomes pressure in the first chamber through pumping hydraulic fluid out the first chamber via the first hot stab.
 11. A subsea intervention device, comprising: an elongated housing comprising a production tree connection interface; a shifting tool disposed within and along a substantial length of the housing and comprising a distal end configured to couple to a tubing plug; and a seal disposed within the housing and formed around a portion of the shifting tool, the seal isolating a first portion of the housing from a second portion of the housing, wherein the second portion of the housing is adjacent to the production tree connection interface, wherein the shifting tool is configured to move partially in and out of the first portion of the housing when there is a pressure differential between the first portion of the housing and an environment external to the first portion of the housing.
 12. The subsea intervention device of claim 11, wherein the first portion of the housing is closed and filled with a hydraulic fluid.
 13. The subsea intervention device of claim 11, further comprising: a first hydraulic coupling point coupled to the first portion of the housing, wherein hydraulic fluid is pumped in and/or out of the first portion of the housing via the hydraulic coupling point; and a second hydraulic coupling point coupled to the second portion of the housing, wherein hydraulic fluid is pumped in and/or out of the second hydraulic coupling point.
 14. The subsea intervention device of claim 11, wherein the shifting tool moves partially out of the first portion of the housing when a pressure in the first portion is greater than a pressure in the environment external to the first portion of the housing.
 15. The subsea intervention device of claim 11, wherein the shifting tool moves back into the first portion of the housing when a pressure in the first portion is less than a pressure in the environment external to the first portion of the housing.
 16. The subsea intervention device of claim 11, wherein the housing is coupled to a production tree via the production tree coupling interface, and the production tree is coupled to a well, and wherein the shifting tool is configured to move partially out of the housing and partially into the well until the shifting tool latches onto a tubing plug disposed within the well, and move back into the housing with the tubing plug, removing the tubing plug from the well.
 17. A method of pulling a tubing plug from a production tubing, comprising: coupling a plug pulling device to a production tree of a well, the plug pulling device comprising a housing and a shifting tool disposed within the housing, the housing divided into a first chamber and a second chamber by a seal, wherein the first chamber is isolated from the second chamber and the second chamber couples to the production tree; opening one or more valves of the production tree; pushing the shifting tool substantially out of the first chamber and into the production tree and the well coupled to the production tree until the shifting tool latches onto the tubing plug disposed within the well; and pulling the shifting tool back into the first chamber along with the tubing plug.
 18. The method of claim 17, comprising: increasing pressure within the first chamber relative to pressure within the second chamber and the production tree until the shifting tool latches onto the tubing plug.
 19. The method of claim 17, comprising: decreasing pressure within the first chamber relative to pressure within the second chamber and the production tree to pull to shifting tool back into the first chamber.
 20. The method of claim 17, wherein pushing the shifting tool substantially out of the first chamber comprises injecting hydraulic fluid into the first chamber, and wherein pulling the shifting tool back into the first chamber comprises removing hydraulic fluid from the first chamber. 